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PJM Report Sees Jump in Energy Prices

Penn Energy | May 22, 2014

PJM Interconnection's wholesale electric energy and capacity markets produced competitive results during the first three months of 2014, according to the 2014 State of the Market Report for PJM: January through March, released by Monitoring Analytics, LLC, the Independent Market Monitor for PJM.

The report is the Independent Market Monitor's assessment of the competitiveness of the wholesale electricity markets managed by PJM in 13 states and the District of Columbia. It analyzes market structure, participant behavior and market performance for each of the PJM markets.

Energy prices in PJM in the first three months of 2014 were set, on average, by units operating at, or close to, their short run marginal costs, although this was not always the case during the high demand hours in January. This is evidence of generally competitive behavior and resulted in a competitive market outcome.

A combination of increased, weather related, demand and higher fuel costs led to a significant increase in energy prices compared to the first three months of 2013. The load-weighted average cost of energy (LMP) increased 148.5 percent in the first three months of 2014 compared to the first three months of 2013, from $37.41 per MWh to $92.98 per MWh.

The price of natural gas increased significantly while the price of coal was relatively flat in the first three months of 2014 compared to the first three months of 2013. As a result of the relative changes in fuel costs, coal-fired units were more competitive with gas-fired units, coal output increased by 18.6 percent and gas output increased by 5.8 percent in the first three months of 2014.

Net revenue is a key measure of overall market performance as well as a measure of the incentive to invest in new generation to serve PJM markets. Energy net revenue for all types of units increased as a result of higher energy prices, even as gas prices rose. Energy net revenues increased by 377 percent for a new gas-fired combined cycle and 637 percent for a new coal plant in the first three months of 2014 compared to the first three months of 2013.

Energy uplift charges increased by $472.6 million or 178.7 percent, from $264.5 million to $737.1 million in the first three months of 2014 compared to the first three months of 2013, primarily as a result of increases in balancing operating reserve charges for reliability and lost opportunity cost charges related to the cold weather.

Total payments for demand response programs increased by $121.5 million or 179.2 percent, from $67.8 million to $189.3 million in the first three months of 2014 compared to the first three months of 2013. The capacity market is the primary source of revenue to participants in PJM demand response programs. In the first three months of 2014, payments to demand response resources in the capacity market increased $71.8 million, or 108.8 percent, from $66.0 million in the first three months of 2013 to $137.8 million in the first three months of 2014.

Congestion costs increased in PJM by $1,050.2 million or 564.8 percent, from $185.9 million to $1,236.1 million in the first three months of 2014 compared to the first three months of 2013. Congestion reflects the underlying characteristics of the power system, including the capability of transmission facilities, the fuel cost and geographic distribution of generation facilities and the geographic distribution of load.

Congestion is neither good nor bad, but is a direct measure of the extent to which there are multiple marginal generating units dispatched to serve load as a result of transmission constraints and the costs of operating those units. ARRs and FTRs served as an effective, but not total, offset against congestion in the first three months of 2014.

ARR and FTR revenues offset 97.5 percent of the total congestion costs in the Day-Ahead Energy Market and the balancing energy market within PJM for the first ten months of the 2013 to 2014 planning period (June 2013 through March 2014).

Electricity prices are probably on their way up across much of the U.S. as coal-fired plants, the dominant source of cheap power, shut down in response to environmental regulations and economic forces.

New and tighter pollution rules and tough competition from cleaner sources such as natural gas, wind and solar will lead to the closings of dozens of coal-burning plants across 20 states over the next three years. And many of those that stay open will need expensive retrofits.

Because of these and other factors, the Energy Department predicts retail power prices will rise 4 percent on average this year, the biggest jump since 2008. By 2020, prices are expected to climb an additional 13 percent, a forecast that does not include the costs of coming environmental rules.

The Obama administration, state governments and industry are struggling to balance this push for a cleaner environment with the need to keep the grid reliable and prevent prices from rocketing too much higher.

"We're facing a set of questions that are new to the industry," says Clair Moeller, who oversees transmission and technology for the Midcontinent Independent System Operator, which coordinates much of the electric grid between Minnesota and Louisiana.

Coal is the workhorse of the U.S. power system. It is used to produce 40 percent of the nation's electricity, more than any other fuel. Because it is cheap and abundant and can be stored on power plant grounds, it helps keep prices stable and power flowing even when demand spikes.

Natural gas, which accounts for 26 percent of the nation's electricity, has dropped in price and become more plentiful because of the fracking boom. But its price is on the rise again, and it is still generally more expensive to produce electricity with gas than with coal. Also, gas isn't stored at power plants because the cost is prohibitive. That means it is subject to shortages and soaring prices.

During the brutally cold and snowy winter that just ended, utilities in several states struggled to secure natural gas because so much was also needed to heat homes. Some utilities couldn't run gas-fired plants at all and power prices soared 1,000 percent in some regions.

As Indiana has reduced its reliance on coal to 84 percent from 97 percent over the last decade, its power prices rose far faster than those of its neighbors and the rest of the country.

"As Indiana's price of electricity becomes less and less competitive, so do we," says Doug Smith, the company's maintenance and engineering manager.

Burning coal releases toxic chemicals, soot and smog-forming chemicals, as well as twice the amount of carbon dioxide that natural gas produces. The Supreme Court last month gave an important approval to one Environmental Protection Agency clean-air rule. That cleared the way for a new rule expected to be announced by President Barack Obama early next month.

This rule, the first to govern emissions of carbon dioxide from existing power plants, could accelerate the move away from coal - if it survives the legal and political challenges that are sure to come.

Already, the current rules are expected to force power companies to shut down 68 coal plants across 20 states between 2014 and 2017, according to Bentek Energy, a market analysis firm.

The Energy Department estimates coal plants with the output to supply 33 million homes will close by 2020.

To meet high demand this past winter, American Electric Power, which serves 5 million customers in 11 states, needed to run 89 percent of the coal plants it will soon have to shut down, says AEP CEO Nick Akins.

This raises concerns that the power system soon won't have enough wiggle room to handle extreme weather, making blackouts more likely.

"It's a warning of what may be to come," Moeller says.

EPA administrator Gina McCarthy, responding to critics, notes that pollution also imposes costs on the economy because it harms human health and the environment. And she has also forcefully promised that the coming carbon dioxide rule will keep costs in check and power flowing.

"EPA is not going to threaten electric reliability," she told a gathering of executives in Houston in March. "That is our No. 1 priority."

Richard Sedano of the Regulatory Assistance Project, which advises officials on regulatory policy, says the transition to cleaner sources can be smooth with proper planning.

States, utilities and the federal government have helped reduce the need for more power plants through efficiency programs and standards for energy-conserving lights and appliances. Utilities are building new transmission lines and updating grids. And customers are generating more of their own power with solar panels and managing their consumption through digital meters and other technology.

Also, power prices across the U.S. are relatively low compared to those in the rest of the developed world. Adjusted for inflation, the national average residential price is nearly 30 percent lower than in 1984.

Natural Gas futures on Thursday lost more ground after the U.S. Energy Information Administration reported that supplies of natural gas rose 106 billion cubic feet for the week ended May 16. Analysts surveyed by Platts forecast an increase of between 101 billion cubic feet and 105 billion cubic feet. Total stocks now stand at 1.27 trillion cubic feet, down 774 billion cubic feet from a year ago and 943 billion cubic feet below the five-year average, the government said. June natural gas was at $4.39 per million British thermal units, down 9 cents, or 1.9%. It was trading at $4.45 before the data.

WTI Crude Trades Near $104 on Economic Data

Bloomberg | May 22, 2014

West Texas Intermediate crude held around $104 a barrel after a Chinese manufacturing gauge rose and data showed more Americans than projected filed applications for unemployment benefits last week. Brent advanced.

WTI for July delivery rose 5 cents to $104.12 a barrel at 9:20 a.m. on the New York Mercantile Exchange. Front-month futures climbed $1.74 to $104.07 yesterday, the highest close since April 21. The volume of all contracts traded was about 17 percent below the 100-day average for the time of day. Prices have gained 5.8 percent this year.

Brent for July settlement increased 35 cents, or 0.3 percent, to $110.90 a barrel on the London-based ICE Futures Europe exchange. Volume was 16 percent above the 100-day average. The futures settled at $110.55 yesterday, the highest closing price since March 3. The European benchmark crude traded at a premium of $6.78 to WTI.

EIA - Weekly Natural Gas Storage Report

Summary

Working gas in storage was 1,266 Bcf as of Friday, May 16, 2014, according to EIA estimates. This represents a net increase of 106 Bcf from the previous week. Stocks were 774 Bcf less than last year at this time and 943 Bcf below the 5-year average of 2,209 Bcf. In the East Region, stocks were 449 Bcf below the 5-year average following net injections of 65 Bcf. Stocks in the Producing Region were 379 Bcf below the 5-year average of 892 Bcf after a net injection of 29 Bcf. Stocks in the West Region were 115 Bcf below the 5-year average after a net addition of 12 Bcf. At 1,266 Bcf, total working gas is below the 5-year historical range.

NYMEX Natural Gas Week-to-Week Price Change

Natural Gas Futures - Five Year Price

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